This invention relates to reservoir simulation and in particular to methodologies for performing simulation of surfactant flooding during enhanced oil recovery (EOR) of a given hydrocarbon reservoir.
Hydrocarbons may be extracted from source rock in a number of stages. Generally, the first stage utilizes the pressure present in the underground reservoir to force the hydrocarbon to the surface through a hole that is drilled from the surface down into the reservoir. This stage continues until the pressure decreases such that it is insufficient to force oil to the surface, requiring additional oil extraction measures.
In the second stage, a number of techniques may be used to recover oil from reservoirs having depleted pressure. These techniques may include the use of pumps to bring the oil to the surface and increasing the reservoir's pressure by injecting water or gas. However, after these methods have been applied, a large percentage of oil often remains trapped in porous rock. The injection of plain salt water alone, for example, may only recover half of the crude oil with the remainder trapped as small oil droplets due to high capillary forces in the micron-size pores in the reservoir rock.
One method of recovering the remaining trapped oil in the reservoir rock is to utilize surfactant EOR. Surfactant EOR is based on the use of surfactants that reduce the interfacial tension (IFT) between the aqueous phase and the hydrocarbon phase, allowing for the mobilization of oil that is trapped in pores.
One tool that is used to minimize the risk associated with the different ways of recovering the hydrocarbons in a reservoir is to create a computer or numerical model to simulate the behavior of the reservoir as it undergoes the different types of recovery processes. Reservoir simulation has become an increasingly widespread and important tool for analyzing and optimizing oil recovery projects. Numerical simulation of large hydrocarbon reservoirs with complex recovery processes is computationally challenging due to the problem size and detailed property calculations involved. This problem is compounded by the finer resolution needed to model such processes accurately.
Currently, there are existing reservoir models which are used to predict the behavior of hydrocarbon reservoirs undergoing surfactant EOR. However, due to the complex nature of the simulation the prior art surfactant EOR models have certain limitations. The prior art reservoir simulations utilize certain physical phenomena in order to accurately predict the behavior of the reservoir undergoing surfactant EOR. Some physical phenomena of the reservoir which are modeled in the prior art simulation models include density, viscosity, velocity-dependent dispersion, molecular diffusion, adsorption, interfacial tension, relative permeability, capillary pressure, capillary trapping, cation exchange, and polymer and gel properties. The present invention, in general, focuses on reservoir simulations undergoing surfactant EOR which include relative permeability models to accurately perform the simulations.
As one skilled in the art will appreciate, surfactant-brine-oil phase behavior affects the relative permeability of a particular reservoir and, as such, needs to be considered as the salinity of the fluids in the reservoir change. Surfactant phase behavior is strongly affected by the salinity of brine present in the reservoirs and in the surfactant formulation. At low brine salinity, a typical surfactant will exhibit good aqueous-phase solubility and poor oil-phase solubility. Thus an overall composition near the brine-oil boundary of the ternary will split into two phases: an excess oil phase that is essentially pure oil and a (water-external) microemulsion phase that contains brine, surfactant, and some solubilized oil. The solubilized oil occurs when globules of oil occupy the central core of the swollen micelles. This type of phase environment is called a Winsor Type II(−) system. II in this context means no more than two phases can (not necessarily will) form, and the − means the tie lines in a phase diagram representing the system will have a negative slope.
For high brine salinities, electrostatic forces drastically decrease the surfactant's solubility in the aqueous phase. An overall composition within the two-phase region will now spilt into an excess brine phase and an (oil-external) microemulsion phase that contains most of the surfactant and some solubilized brine. The + means that the tie lines in a phase diagram representing the system will have a positive slope.
At salinities between those of Type II(−) and II(+) systems, there must be a continuous change between these systems. This occurs within a range of salinities where a third surfactant-rich phase is formed. An overall composition within the three-phase region separates into excess oil and brine phases, as in the Type II(−) and II(+) environments, and into a microemulsion phase whose composition is represented by an invariant point. This environment is called a Winsor Type III system.
Currently, there is no numerical model which can simulate the relative permeability characteristics of a reservoir which covers full spectrum of phase behavior and maintains the physical consistency during the transition from Type II(−) to III to Type II(+) system and vice versa. Prior art models, including UTCHEM, the University of Texas Chemical Compositional Simulator, can only successfully simulate a chemical flood that operates at a condition where the phase diagram varies between Type II(−) and Type III or at a condition where the phase diagram varies between Type II(+) and Type III. The prior art reservoir simulators cannot model the reservoir correctly if the phase diagram traverses all three phase types. Thus, there exists a need for improved methods for performing reservoir simulations which include surfactant EOR.